Drilling Fluids Approaches for Control of Wellbore Instability in Fractured Formations

2003 ◽  
Author(s):  
Franck Labenski ◽  
Paul Reid ◽  
Helio Santos
Keyword(s):  
Drilling Fluids ◽  
Wellbore Instability

scholarly journals Experimental study of Zubair shale stability of east Baghdad oil field using different additives in water based mud

2019 ◽  
Vol 10 (3) ◽  
pp. 1215-1225
Author(s):  
Asawer A. Alwassiti ◽  
Mayssaa Ali AL-Bidry ◽  
Khalid Mohammed
Keyword(s):  
Drilling Fluid ◽  
Oil Field ◽  
Oil Fields ◽  
Drilling Fluids ◽  
Fluid Type ◽  
Wellbore Instability ◽  
Immersion Period ◽  
Shale Formation ◽  
Shale Recovery ◽  
Polymer Type

AbstractShale formation is represented as one of the challenge formations during drilling wells because it is a strong potential for wellbore instability. Zubair formation in Iraqi oil fields (East Baghdad) is located at a depth from 3044.3 to 3444 m. It is considered as one of the most problematic formations through drilling wells in East Baghdad. Most problems of Zubair shale are swelling, sloughing, caving, cementing problem and casing landing problem caused by the interaction of drilling fluid with the formation. An attempt to solve the cause of these problems has been adapted in this paper by enhancing the shale stability through adding additives to the drilling fluid. The study includes experiments by using two types of drilling fluids, API and polymer type, with five types of additives (KCl, NaCl, CaCl2, Na2SiO3 and Flodrill PAM 1040) in different concentrations (0.5, 1, 5 and 10) wt% and different immersion period (1, 24 and 72 h) hours. The effect of drilling fluids and additive salts on shale has been studied by using different techniques: (XRD, XRF, reflected and transmitted microscope) as well shale recovery. The results show that adding 10 wt% of Na2SiO3 to API drilling fluid results in a high percentage of shale recovery (78.22%), while the maximum shale recovery was (80.57%) in polymer drilling fluid type gained by adding 10 wt% of Na2SiO3.

scholarly journals Chemical Effect on Wellbore Instability of Nahr Umr Shale

2013 ◽  
Vol 2013 ◽  
pp. 1-7 ◽  
Author(s):  
Baohua Yu ◽  
Chuanliang Yan ◽  
Zhen Nie
Keyword(s):  
Drilling Fluid ◽  
Ionic Concentration ◽  
Chemical Effect ◽  
Drilling Fluids ◽  
Collapse Pressure ◽  
Wellbore Instability ◽  
Sealing Capacity ◽  
Engineering Data ◽  
Forward Engineering ◽  
Rock Mechanical Properties

Wellbore instability is one of the major problems that hamper the drilling speed in Halfaya Oilfield. Comprehensive analysis of geological and engineering data indicates that Halfaya Oilfield features fractured shale in the Nahr Umr Formation. Complex accidents such as wellbore collapse and sticking emerged frequently in this formation. Tests and theoretical analysis revealed that wellbore instability in the Halfaya Oilfield was influenced by chemical effect of fractured shale and the formation water with high ionic concentration. The influence of three types of drilling fluids on the rock mechanical properties of Nahr Umr Shale is tested, and time-dependent collapse pressure is calculated. Finally, we put forward engineering countermeasures for safety drilling in Halfaya Oilfield and point out that increasing the ionic concentration and improving the sealing capacity of the drilling fluid are the way to keep the wellbore stable.

scholarly journals Oil-Based Drilling Fluid Plugging Method for Strengthening Wellbore Stability of Shale Gas

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Pengcheng Wu ◽  
Chengxu Zhong ◽  
Zhengtao Li ◽  
Zhen Zhang ◽  
Zhiyuan Wang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Drilling Fluid ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Fluid System ◽  
Horizontal Drilling ◽  
Wellbore Instability ◽  
Filtration Loss ◽  
Treatment Agent ◽  
Stability Method

Finding out the reasons for wellbore instability in the Longmaxi Formation and Wufeng Formation and putting forward drilling fluid technical countermeasures to strengthen and stabilize the wellbore are very crucial to horizontal drilling. Based on X-ray diffraction, electron microscope scanning, linear swelling experiment, and hot-rolling dispersion experiment, the physicochemical mechanism of wellbore instability in complex strata was revealed, and thus, the coordinated wellbore stability method can be put forward, which is “strengthening plugging of micropores, inhibiting filtrate invasion, and retarding pressure transmission.” Using a sand bed filtration tester, high-temperature and high-pressure plugging simulation experimental device, and microporous membrane and other experimental devices, the oil-based drilling fluid treatment agent was researched and selected, and a set of an enhanced plugging drilling fluid system suitable for shale gas horizontal well was constructed. Its temperature resistance is 135°C and it has preferable contamination resistibility (10% NaCl, 1% CaCl2, and 8% poor clay). The bearing capacity of a 400 μm fracture is 5 MPa, and the filtration loss of 0.22 μm and 0.45 μm microporous membranes is zero. Compared with previous field drilling fluids, the constructed oil-based drilling fluid system has a greatly improved plugging ability and excellent performance in other aspects.

Wellbore Shielding Technique Increases Operative Window, Avoiding Formation Instability and Losses, Minimizing NPT, and Optimizing Drilling Operations in the Unconventional Plays

2021 ◽  
Author(s):  
Gaston Lopez ◽  
Gonzalo Vidal ◽  
Claus Hedegaard ◽  
Reinaldo Maldonado
Keyword(s):  
Drilling Fluid ◽  
Drilling Fluids ◽  
Wellbore Instability ◽  
Lost Circulation ◽  
Drilling Performance ◽  
Drilling Parameters ◽  
Vaca Muerta ◽  
Drilling Operations ◽  
Fracture Gradient ◽  
Vaca Muerta Formation

Abstract Losses, wellbore instability, and influxes during drillings operations in unconventional fields result from continuous reactivity to the drilling fluid causing instability in the microfractured limestone of the Quintuco Formation in Argentina. This volatile situation becomes more critical when drilling operations are navigating horizontally through the Vaca Muerta Formation, a bituminous marlstone with a higher density than the Quintuco Formation. Controlling drilling fluids invasion between the communicating microfractures and connecting pores helps to minimize seepage losses, total losses, wellbore fluid influxes, and instabilities, reducing the non-productive time (NPT) caused by these problems during drilling operations. The use of conventional sealants – like calcium carbonate, graphite, asphalt, and other bridging materials – does not guarantee problem-free drilling operations. Also, lost circulation material (LCM) is restricted because the MWD-LWD tools clearances are very narrow in these slim holes. The challenge is to generate a strong and resistant seal separating the drilling fluid and the formation. Using an ultra-low-invasion technology will increase the operative fracture gradient window, avoid fluid invasion to the formation, minimize losses, and stop the cycle of fluid invasion and instability, allowing operations to maintain the designed drilling parameters and objectives safely. The ultra-low-invasion wellbore shielding technology has been applied in various fields, resulting in significantly improved drilling efficiencies compared to offset wells. The operator has benefited from the minimization of drilling fluids costs and optimization in drilling operations, including reducing the volume of oil-based drilling fluids used per well, fewer casing sections, and fewer requirements for cementing intervals to solve lost circulation problems. This paper will discuss the design of the ultra-low-invasion technology in an oil-based drilling fluid, the strategy for determining the technical limits for application, the evaluation of the operative window with an increase in the fracture gradient, the optimized drilling performance, and reduction in costs, including the elimination of NPT caused by wellbore instability.

Predrill Geomechanical Evaluation Helps in Successful Drilling in High Depletion Wells in a Mature Field, Offshore Sarawak, Malaysia

2021 ◽  
Author(s):  
Mohamad Hafiz Abdul Latip ◽  
Avirup Chatterjee ◽  
Amitava Ghosh ◽  
Priveen Raj Santha Moorthy
Keyword(s):  
Stress Path ◽  
Wellbore Stability ◽  
Drilling Fluids ◽  
Drilling Mud ◽  
Wellbore Instability ◽  
Pressure Depletion ◽  
Loss Event ◽  
Mature Field ◽  
The Stability ◽  
Fracture Gradient

Abstract Hydrocarbon-bearing reservoirs in a mature field, offshore Sarawak, Malaysia, contains multiple reservoir cycles interbedded with weak shale and coal formations. Years of production from these reservoirs caused significant pressure depletion, as well as reduced fracture gradient and a narrower drilling mud weight window. An improperly weighted mud may induce wellbore instability in weaker, but normally pressured, formations or mud losses in the heavily depleted reservoirs. Globally, mud losses are considered the most expensive well control operation incidents. Earlier drilling campaigns in ths field encountered numerous wellbore instability incidents; hence, a study was conducted to develop an understanding of the drilling issues and assess the stability of the heavily depleted reservoirs. Collaboration between the drilling and geomechanics teams facilitated better understanding of the stability challenges and helped in mitigating risk related to wellbore instability. A field scale geomechanical model was developed and validated using data from exploration and development wells from different phases of drilling in the study area. The stress path factor (SPF), which determines the reduction in fracture gradient with pore pressure depletion is crucial for defining drilling mud windows, is difficult to constrain in the absence of measured formation fracturing data in virgin and depleted reservoirs. A mud loss event in the depleted zone from a recent drilled well and regional information were used to estimate the range of SPF in the study area. Recorded bottom hole pressures from pressure while drilling (PWD) data suggested that the maximum equivalent circulating density (ECD) recorded was close or within the depleted section. The loss event was associated with reduced fracture gradient due to depletion from its pre-depleted range. This paper describes how geomechanical evaluation with effective well drilling practices and fit for purpose-drilling fluids have helped drilling through depleted reservoirs with ECD management. At the end, it shows a comparison of the predrill wellbore stability mud weight estimates with the actual mud weights used to successfully drill and complete the planned wells.

Application of Artificial Clay Samples (Pellets) in Laboratory Testing of Shale/Drilling Fluid Interaction

2013 ◽  
Author(s):  
Borivoje Pasic ◽  
Nediljka Gaurina-Medjimurec ◽  
Bojan Moslavac
Keyword(s):  
Laboratory Testing ◽  
Drilling Fluid ◽  
Petroleum Industry ◽  
Drilling Fluids ◽  
Surface Sampling ◽  
Laboratory Equipment ◽  
Wellbore Instability ◽  
Research Activities ◽  
Physico Chemical ◽  
Fluid Interaction

Wellbore instability was and is one of the most frequent problems in petroleum industry, especially in the drilling operations. It is mainly caused by the shale formations which represent 75% of all drilled formations. The wellbore instability problems involve tight hole spots, wellbore diameter enlargement, the appearance of cavings, the inability of carrying out wireline operations, poor hole cleaning, unsuccessful wellbore cementing operations and other. The wellbore instability is the result of mechanical and physico-chemical causes mostly acting concurrently. The shale instability basically comes out of its mineralogical composition (especially clay minerals content) and physico-chemical properties. Shale-mud interaction includes water/ions movement in and out of the shales due to pressure differential, osmosis, diffusive flow and capillary pressure. Many research activities about shale instability causes and shale properties (affecting shale behavior) definition have been carried out by now. Different shale samples, laboratory equipment and inhibitive muds have been used. Laboratory tested shale samples are provided by the wellbore cores, surface sampling or, which is the simplest method, by collecting the samples at the shale shakers during drilling operation. The amount of these samples is not enough for laboratory testing. Another problem is closely connected to sample quality and preservation. There are also differences in drilling fluids used in these laboratory tests, especially in their composition (sometimes containing more than one shale inhibitor). It is difficult to compare test results and conclusions made by different authors. The laboratory study presented within this paper are done with artificial clay samples (pellets) made by compacting the powderish material containing exact quantity of quartz, montmorillonite and kaolinite. The laboratory testing is done by treating the powderish samples inside the desiccator (24 hours), compacting (30 minutes), swelling (24 hours) and drying samples (24-hour). Sample swelling is tested by using different mud types and the sample mass is measured in each above mentioned phase. Special attention is directed to preparation and pellets content definition as a good replacement for the original shale in laboratory testing of shale and drilling fluid interaction. The influence of used muds on the total pellet swelling and swelling intensity, especially at the early phase of testing was determined.

scholarly journals Alkali Solution Erodes Shale: Influencing Factors and Structural Damage Characteristics

2018 ◽  
Vol 2018 ◽  
pp. 1-8
Author(s):  
Jiping She ◽  
Hao Zhang ◽  
Ying Zhong ◽  
Yang Yuan ◽  
Jiachun You
Keyword(s):  
Corrosion Rate ◽  
Shale Gas ◽  
Structural Damage ◽  
Reaction Rate ◽  
Fracture Propagation ◽  
Drilling Fluids ◽  
Gas Wells ◽  
Wellbore Instability ◽  
High Ph ◽  
Bedding Planes

High-pH drilling fluids are often used for drilling shale gas wells. Alkali erosion of shale is one of the important factors of wellbore instability. Alkali erosion experiments of different kinds of minerals and shale were conducted in this paper. Experimental results show that the corrosion rate of kaolinite is the highest when the pH is 9, the corrosion rate of smectite is the highest when the pH is 10 or 11, and the corrosion rate of the quartz is the highest when the pH is 12. Both shale particle size and concentration of hydroxide ion all affect the reaction rate, and the former has a negative correlation with the reaction rate, and the latter has a positive correlation with the reaction rate. In addition, alkaline erosion can lead to the fracture propagation along the bedding planes of shale, which can easily result in wellbore instability. This study may offer some theoretical basis for wellbore instability induced by high-pH drilling fluids.

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